In rotary drilling operations, a drill bit is attached to the end of a bottom hole assembly which is attached to a drill string comprising drill pipe and tool joints which may be rotated at the surface by a rotary table or top drive unit. The weight of the drill string and bottom hole assembly causes the rotating bit to bore a hole in the earth. As the operation progresses, new sections of drill pipe are added to the drill string to increase its overall length. Periodically during the drilling operation, the open borehole is cased to stabilize the walls, and the drilling operation is resumed. As a result, the drill string usually operates both in the open borehole and within the casing which has been installed in the borehole. Alternatively, coiled tubing may replace drill string in the drilling assembly. The combination of a drill string and bottom hole assembly or coiled tubing and bottom hole assembly is referred to herein as a drill stem assembly. Rotation of the drill string provides power through the drill string and bottom hole assembly to the bit. In coiled tubing drilling, power is delivered to the bit by the drilling fluid pumps. The amount of power which can be transmitted by rotation is limited to the maximum torque a drill string or coiled tubing can sustain.
During the drilling of a borehole through underground formations, the drill stem assembly undergoes considerable sliding contact with both the steel casing and rock formations. This sliding contact results primarily from the rotational and axial movements of the drill stem assembly in the borehole. Friction between the moving surface of the drill stem assembly and the stationary surfaces of the casing and formation creates considerable drag on the drill stem and results in excessive torque and drag during drilling operations. The problem caused by friction is inherent in any drilling operation, but it is especially troublesome in directionally drilled wells or extended reach drilling (ERD) wells. Directional drilling or ERD is the intentional deviation of a wellbore from the vertical. In some cases the angle from the vertical may be as great as ninety degrees from the vertical. Such wells are commonly referred to as horizontal wells and may be drilled to a considerable depth and considerable distance from the drilling platform.
In all drilling operations, the drill stem assembly has a tendency to rest against the side of the borehole or the well casing, but this tendency is much greater in directionally drilled wells because of the effect of gravity. As the drill string increases in length or degree of vertical deflection, the amount of friction created by the rotating drill stem assembly also increases. To overcome this increase in friction, additional power is required to rotate the drill stem assembly. In some cases, the friction between the drill stem assembly and the casing wall or borehole exceeds the maximum torque that can be tolerated by the drill stem assembly and/or maximum torque capacity of the drill rig and drilling operations must cease. Consequently, the depth to which wells can be drilled using available directional drilling equipment and techniques is limited.
One method for reducing the friction caused by the contact between the drill stem assembly and casing (in case of a cased hole) or borehole (in case of an open hole) is improving the lubricity of drilling muds. In industry drilling operations, attempts have been made to reduce friction through, mainly, using water and/or oil based mud solutions containing various types of expensive and often environmentally unfriendly additives. Diesel and other mineral oils are also often used as lubricants, but there is a problem with the disposal of the mud. Certain minerals such as bentonite are known to help reduce friction between the drill stem assembly and an open borehole. Materials such as Teflon have been used to reduce friction, however these lack durability and strength. Other additives include vegetable oils, asphalt, graphite, detergents and walnut hulls, but each has its own limitations.
Another method for reducing the friction between the drill stem assembly and the well casing or borehole is to use aluminum drill string because aluminum is lighter than steel. However, the aluminum drill string is expensive and is difficult to use in drilling operations, and it is not compatible with many types of drilling fluids (e.g. drilling fluids with high pH).
Yet another method for reducing the friction between the drill stem assembly and the well casing or borehole is to use a hard facing material on the drill string assembly (also referred to herein as hardbanding or hardfacing). U.S. Pat. No. 4,665,996, herein incorporated by reference in its entirety, discloses the use of hardfacing the principal bearing surface of a drill pipe with an alloy having the composition of: 50-65% cobalt, 25-35% molybdenum, 1-18% chromium, 2-10% silicon and less than 0.1% carbon for reducing the friction between the drill string and the casing or rock. As a result, the torque needed for the rotary drilling operation, especially directional drilling, is decreased. The disclosed alloy also provides excellent wear resistance on the drill string while reducing the wear on the well casing. Another form of hardbanding is WC-cobalt cermets applied to the drill stem assembly. Other hardbanding materials include TiC, Cr-carbide, Nb-carbide and other mixed carbide, carbonitride, boride and nitride systems. Hardbanding may be applied to portions of the drill stem assembly using weld overlay or thermal spray methods.
U.S. Patent Publication No. 2002/0098298 discloses hardbanding applied in a pattern on the surface of a tool joint for the purpose of reducing hydraulic drag. “By providing wear-reducing material in separate, defined spaced-apart areas, fluid flow in a wellbore annulus past a tool joint is enhanced, i.e. flow between deposit areas is facilitated.” This reference further discloses low friction materials wherein the low friction material is a component element of the hardbanding material such as chromium. “The minimal admixture of the base material permits an extremely accurate pre-engineering of the matrix chemistry, allowing customization of the material and tailoring the tool joint to address drilling needs, such as severe abrasion, erosion, and corrosion, as seen, e.g., in open hole drilling conditions. It also permits modification of the deposit to adjust to coefficient of friction needs in metal-to-metal friction, e.g. as encountered in rotation of the drill string within the casing. In certain aspects the deposited material is modified by replacing galling material, e.g., iron and nickel, with non-galling elements, such as e.g., but not limited to, molybdenum, cobalt and chromium and combinations thereof.”
U.S. Pat. No. 5,010,225 discloses the use of grooves in the hardbanding to prevent casing wear. The protruding area is free of tungsten carbide particles so that tungsten carbide particle contact with the casing is avoided. The recessed area is about 80% of the total surface area.
U.S. Pat. Nos. 7,182,160, 6,349,779 and 6,056,073 disclose the designs of grooved segments in drill strings for the purpose of improving fluid flow in the annulus and reducing contact and friction with the borehole wall.
In addition to hardbanding on tool joints, certain sleeved devices have been used in the industry. A polymer-steel based wear device is disclosed in U.S. Pat. No. 4,171,560 (Garrett, “Method of Assembling a Wear Sleeve on a Drill Pipe Assembly”). Western Well Tool subsequently developed and currently offers Non-Rotating Protectors to control contact between pipe and casing in deviated wellbores, the subject of U.S. Pat. Nos. 5,803,193, 6,250,405, and 6,378,633.
Strand et al. have patented a metal “Wear Sleeve” device (U.S. Pat. No. 7,028,788) that is a means to deploy hardbanding material on removable sleeves. This device is a ring that is typically of less than one-half inch in wall thickness that is threaded onto the pin connection of a drill pipe tool joint over a portion of the pin that is of reduced diameter, up to the bevel diameter of the connection. The ring has internal threads over a portion of the inner surface that are of left-hand orientation, opposite to that of the tool joint. Threaded this way, the ring does not bind against the pin connection body, but instead it drifts down to the box-pin connection face as the drill string turns to the right. Arnco markets this device under the trade name “WearSleeve.” After several years of availability in the market and at least one field test, this system has not been used widely.
Arnco has devised a fixed hardbanding system typically located in the middle of a joint of drill pipe as described in U.S. Patent Publication No. 2007/0209839, “System and Method for Reducing Wear in Drill Pipe Sections.”
Separately, a tool joint configuration in which the pin connection is held in the slips has been deployed in the field, as opposed to the standard petroleum industry configuration in which the box connection is held by the slips. Certain benefits have been alleged, as documented in exemplary publications SPE 18667 (1989) Dudman, R. A. et. al, “Pin-up Drillstring Technology: Design, Application, and Case Histories,” and SPE 52848 (1999) Dudman, R. A. et. al, “Low-Stress Level Pin Up Drill string Optimizes Drilling of 20,000 ft Slim-Hole in Southern Oklahoma.” Dudman discloses larger pipe diameters and connection sizes for certain hole sizes than may be used in the standard pin-down convention, because the pin connection diameter can be made smaller than the box connection diameter and still satisfy fishing requirements.
Still another problem encountered during subterraneous rotary drilling operations, especially directional drilling, is the wear on the casing and drill stem assembly that occurs when the metal surfaces contact each other. This abrasion between metal surfaces during the drilling of oil and gas wells results in excessive wear on both the drill stem assembly and the well casing. Presently, one preferred solution to reduce wear of drill stem assemblies is to hardface portions of the drill stem assembly. A tungsten carbide containing alloy, such as Stellite 6 and Stellite 12 (trademark of Cabot Corporation), has excellent wear resistance as a hardfacing material. Hardfacing protects the drill stem assembly, but it tends to cause excessive abrading of the well casing. This problem is especially severe during directional drilling because the drill stem assembly, which has a tendency to rest on the well casing, continually abrades the well casing as the drill string rotates. In addition, some of these hardfacing alloys, such as tungsten carbide, may make the friction problem worse.